Utility networks provide an electrical power system to utility customers. In modern utility networks, the network comprises the utility power source, consumer loads, and distributed resources (DR). Distributed resources are resources that can also supply electrical power to the network. The number and types of distributed resources is growing rapidly and can include photovoltaics, wind, hydro, fuel cells, storage systems such as battery, super-conducting flywheel, and capacitor types, and mechanical means including conventional and variable speed diesel engines, Stirling engines, gas turbines, and micro-turbines. These DRs are connected to the utility network such that they operate in parallel with the utility power sources.
One common problem faced by modern utility networks is the occurrence of islanding. Islanding is the condition where a DR is severed from the utility network, but continues to supply power to portions of the utility network after the utility power supply is disconnected from those portions of the network. The island condition complicates the orderly reconnection of the utility network and poses a hazard to utility personnel as well as equipment. Thus, it is important for an island condition to be detected and subsequently eliminated.
Several techniques have been proposed to guard against islanding. For example, one method involves the monitoring of auxiliary contacts on all circuit breakers of the utility system between its main source of generation and DRs. The auxiliary contacts are monitored for a change of state which represents an open circuit breaker on the utility source. The utility circuit breaker is typically monitored and tripped by external protective relays. When a loss of utility is detected by the change in state of the auxiliary contact of a circuit breaker, a transferred trip scheme is employed to open the interconnection between the utility and the DR. A transferred trip scheme uses the auxiliary contacts of the utility source being monitored. The auxiliary contacts are connected in parallel with other devices which can trigger the trip of the local interconnection breaker. When the auxiliary contacts change state, a trip is induced on the local interconnection breaker. This prevents an island condition from occurring. The drawback of such a method is that often the point of utility isolation (the point at which the utility circuit breaker opens) is of such a distance from the local DR that running a contact status signal back to the local DR control system is not practical.
Another method of detecting an island condition is to use known over/under frequency (e.g. 81 o,u) and known under and over voltage (e.g. 27,59) protective relays at, or below (within the local distribution system) the point of interconnection to determine when an island condition exists. The use of these protective relays relies upon the probability that the load being produced by the local DR is not exactly matched to the load produced by the island event. During normal operation (no island event present), a local DR supports a load on the network by supplying power at a normal voltage and frequency (usually the system voltage and frequency). When an island event occurs, the local DR becomes the only power source for a portion of the network. If the load on that portion of the islanded network is different from the load supplied by the local DR before the island event, the voltage and frequency at which the local DR supplies power will be affected.
FIGS. 7-12 illustrate this for a conventional system with two generators (labeled 1 and 2 on the graphs) paralleled to a utility power source (labeled 3 on the graphs) and a resistive load. Each generator is a distributed resource (H1 and H2). FIG. 7 shows the voltage and frequency response under normal operating conditions. FIG. 8 shows the response when the load at islanding is greater than the power supplied by the generators prior to islanding at T=1 second. Note the drop in frequency on both generators while the utility frequency remains constant. FIG. 9 shows the response when the load at islanding is less than the power supplied by the generators prior to islanding at T=1 second. Note the rise in frequency on both generators while the utility frequency remains constant. FIG. 10 shows the response when the load at islanding is equal to the power supplied by the generators prior to islanding at T=1 second. Note the constant frequency on both generators and the utility. This condition would not be detected by under/over frequency protective relays. FIG. 11 shows the response when the load at islanding is larger than the rated generator capacity prior to islanding at T=1 second. Note the degradation in generator frequency from 60 Hz (376.8 r/sec) to approximately 59 Hz (300 r/sec) in less than 2 seconds. This disruption would likely be picked up by under/over voltage and frequency protective relays (passive detection). FIG. 12 shows the response when the load at islanding is slightly larger than the maximum generator capacity prior to islanding at T=1 second. Note the long decay period of the generator frequency. The frequency changes from 60 Hz to 59.4 Hz in over 5 seconds. This situation would lead to long trip times using only passive island detection.
If, for instance, the KW (real) load is less than that of the islanded system at the time of islanding, an increase in local frequency will occur (see FIG. 9). The amplitude of this frequency change is determined by the difference in the load on the DR at the time of islanding, and the load on the islanded system. The period of the frequency change is dependent upon the response of the DR. If the DR is a generator, for example, the period of the frequency change is dependent upon the response of the generator speed governor and the acceleration characteristic of the generator, which control the rate of change in the speed of the generator.
Conversely, if the load on the islanded system is greater than that on the DR at the instant islanding occurs, then the frequency of the DR will drop in response to the increased load (see FIG. 8). Similarly, DR voltage will increase or decrease depending on the VAR (reactive) loads imposed upon the generator at the time of islanding.
As can be seen from the figures, the techniques described above do not detect all island conditions. If the DR is supplying exactly the same real and reactive load as is being consumed by the loads on the utility network, the resulting island condition is not detectable by conventional techniques. There will be no discernable shift in the frequency or voltage of the islanded system as the DR is perfectly supplying the islanded loads. When a system is operating at or near this balance, there is a non-detection area where traditional over/under frequency and over/under voltage relays either fail to detect, or are slow to detect the islanded condition (see FIG. 10).
These and other drawbacks and disadvantages exist in conventional systems and methods.